Method of Heterogeneous Etching of Sandstone Formations

ABSTRACT

The invention provides a method of treating a sandstone-containing subterranean formation penetrated by a wellbore. The method is carried out by forming a slurry of a carrier fluid containing a viscosifying agent and encapsulated particles of a hydrogen fluoride source without settling of the particles. The carrier fluid may be an acid-based carrier fluid. The encapsulated hydrogen fluoride source may be encapsulated with a solid polymer acid precursor. The hydrogen fluoride source is present within the slurry in an amount of about 10% or more by weight of the slurry. The slurry is introduced into the wellbore at a pressure above the fracture pressure of the formation under conditions wherein the hydrogen fluoride source is released.

BACKGROUND

The invention relates to stimulation of wells penetrating subterranean formations. More particularly it relates to acid fracturing; most particularly it relates methods of etching differentially the fracture faces of sandstone formations so that etching provides a conductive path from the fracture tip to the wellbore.

The statements in this section merely provide background information related to the present disclosure and may not constitute prior art.

There exist several stimulation treatments for increasing production from hydrocarbon reservoirs, such as fracture stimulation. Proppant fracturing treatments consist of injecting fluid into a well at a certain rate and under a certain pressure for fracturing the reservoir and fixing the fracture with a propping agent that prevents the fracture from closing. This method is used for both carbonate and sandstone formations.

Acid fracturing is an alternative to proppant fracturing and is commonly used in the treatment of carbonate formations with the same objectives of creating long, open, conductive channels from the wellbore, extending deep into the formation. The difference between the two fracturing methods is in how the fracture conductivity is created and maintained. Fracture acidizing does not utilize proppant to hold the fracture open, but relies on the non-uniform etching of fracture faces with acid, resulting in the formation of conductive channels. Such acid fracturing has been reserved exclusively to carbonate formations.

The treatment of carbonate formations with acid works well because of the favorable kinetics of carbonate dissolution by the acid. A variety of different acids may be used in treating carbonate formations. The etching of carbonate surfaces of the formation appears to be non-uniform due to inhomogeneties in the formation composition that lead to uneven diffusion-limited reaction with the rock. This results in disparities in the opposing fracture faces that do not match up when the fracture pressure is released so that “pillars” are formed that support the fracture wall after closure and provides conductive channels or flow paths to facilitate production of fluids from the formation to the wellbore.

In contrast to carbonate formations, sandstone formations are only susceptible to dissolution by hydrofluoric acid. The reaction-rate-limiting kinetics of sandstone dissolution by hydrogen fluoride results in uniform etching of the sandstone surfaces so that no pillars or channels of the formation are formed after the fracture has closed.

Accordingly, a need exists for a method for using acid fracturing techniques in sandstone formations to form conductive fractures.

SUMMARY

This invention relates to a method of treating a sandstone-containing subterranean formation penetrated by a wellbore. In certain embodiments a slurry of a carrier fluid containing a viscosifying agent and encapsulated particles of a hydrogen fluoride source is formed. The hydrogen fluoride source is present in the slurry in an amount of about 10% by weight or more of the slurry. The encapsulated hydrogen fluoride source is dispersed within the slurry without settling of the particles and the slurry is introduced into the wellbore at a pressure at or above the fracture pressure of the formation under conditions wherein the hydrogen fluoride source is released, which may result in increased production of fluids from the wellbore.

In more specific embodiments, the hydrogen fluoride source is encapsulated within a solid polymer acid precursor. Examples of such solid polymer acid precursors that may be used include homopolymers of lactic acid, glycolic acid, hydroxybutyrate, hydroxyvalerate and epsilon caprolactone, random copolymers of at least two of lactic acid, glycolic acid, hydroxybutyrate, hydroxyvalerate, epsilon caprolactone, L-serine, L-threonine, L-tyrosine, block copolymers of at least two of polyglycolic acid, polylactic acid, hydroxybutyrate, hydroxyvalerate, epsilon caprolactone, L-serine, L-threonine, L-tyrosine, homopolymers of ethylenetherephthalate (PET), butylenetherephthalate (PBT) and ethylenenaphthalate (PEN), random copolymers of at least two of ethylenetherephthalate, butylenetherephthalate and ethylenenaphthalate, block copolymers of at least two of ethylenetherephthalate, butylenetherephthalate, ethylenenaphthalate and combinations of these.

The hydrogen fluoride source may be encapsulated within various materials. The encapsulating material may make up from about 0.1% to about 30% by weight of the slurry. Some of these materials may include acrylics, halocarbon, polyvinyl alcohol, Aquacoat® aqueous dispersions, hydrocarbon resins, polyvinyl chloride, Aquateric® enteric coatings, hydroxypropyl cellulose (HPC), polyvinylacetate phthalate, hydroxypropyl methyl cellulose (HPMC), polyvinylidene chloride, hydroxylpropyl methyl cellulose phthalate (HPMCP), proteins, Kynar®, fluoroplastics, rubber (natural or synthetic), caseinates, maltodextrins, shellac, chlorinated rubber, silicone, polyvinyl acetate phtalate (e.g. Coateric®) coatings, microcrystalline wax, starches, coating butters, milk solids, stearines, polyvinyl dichloride (Daran®) latex, molasses, sucrose, dextrins, nylon, surfactants, Opadry® combined polymer/plasticizer coating systems, Surelease® coating systems which are combination of film-forming polymer; plasticizer and stabilizers for sustained release, enterics, paraffin wax, Teflon® fluorocarbons, Eudragits® polymethacrylates, phenolics, waxes, ethoxylated vinyl alcohol, vinyl alcohol copolymer, polylactides, zein, fats, polyamino acids, fatty acids, polyethylene gelatin, polyethylene glycol, glycerides, polyvinyl acetate, vegetable gums and polyvinyl pyrrolidone.

The carrier fluid used in forming the slurry may be an acid-based fluid. Examples of acid-forming materials include hydrochloric acid, nitric acid, hydroiodic acid, hydrobromic acid, sulfuric acid, sulfamic acid, phosphoric acid, formic acid, acetic acid, halogenated derivatives of acetic acid, citric acid, propionic acid, tartaric acid, lactic acid, glycolic acid, aminopolycarboxylic acids, sulfamic acid, malic acid, maleic acid, methylsulfamic acid, chloroacetic acid, 3-hydroxypropionic acid, polyaminopolycarboxylic acid, bisulfate salts and combinations of these.

The hydrogen fluoride source may make up from about 50% to 99% by weight of the encapsulated particles. Suitable examples for the hydrogen fluoride source include hydrofluoric acid, ammonium fluoride, ammonium bifluoride, fluoroboric acid, hexafluorophosphoric acid, difluorophosphoric acid, fluorosulfonic acid, polyvinylammonium fluoride, polyvinylpyridinium fluoride, pyridinium fluoride, imidazolium fluoride, sodium tetrafluoroborate, ammonium tetrafluoroborate, salts of hexafluoroantimony, polytetrafluoroethylene polymers, and combinations of these.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of the present invention, and the advantages thereof, reference is now made to the following descriptions taken in conjunction with the accompanying figures, in which:

FIG. 1 is an image showing a Berea sandstone core prior to treatment;

FIG. 2 is an image showing a Berea sandstone core that has been treated with an encapsulated hydrogen fluoride source in accordance with the present invention; and

FIG. 3 is an image showing a Berea sandstone core that has been treated with a non-encapsulated hydrogen source.

DETAILED DESCRIPTION

Due to the very slow kinetics of sandstone surface dissolution with hydrofluoric acid (HF), no heterogeneous etched pattern is created at the fracture faces of sandstone formations once treated with HF solution. As a result, without proppant materials, there is nothing preventing the fracture closure once pressure is released, if attempts at acid fracturing of such formations are made. Sandstone formations are typically comprised of quartz and clay components (e.g. 80% quartz, 20% clays), which are not readily dissolved by acids commonly used in the acid fracturing of carbonate formations. Typically, sandstone formations typically have a clay content of no more than 35% by weight. Typically minerals found in sandstone formations include quartz, feldspars, micas, clays (e.g. chlorite, kaolonite, illite, smectite), carbonates, sulfates, halites, iron oxides, etc. The present invention provides a method of preferentially etching some regions of the fracture surfaces created in sandstone formations in order to create a conductive path from the fracture tip to the wellbore.

In treating a subterranean sandstone formation penetrated by a wellbore in an acid-fracturing treatment, a slurry of encapsulated etching material is injected into the fracture. The encapsulated materials are heterogeneously positioned within the fracture of portions of a sandstone formation so that they are dispersed along the fracture wall. Once in the fracture, the encapsulated etching agent is released. In this manner, some portions of the surface are in contact with very high concentrations of the acid etching agent, while other areas are not. This results in the preferential etching of the fracture faces. The remaining portions of the surface that remain intact leave behind “pillars” that keep the fracture open and create conductive flow channels, so that there is an increase in production of fluids from the formation to the wellbore.

For sandstone formations, the etching material provides a source of hydrogen fluoride (HF), which etches the sandstone formation upon its release. The source of hydrogen fluoride is a solid hydrogen fluoride source material, that is the material is substantially insoluble or only slightly soluble in basic or approximately neutral aqueous fluids. In acidic aqueous fluids, the hydrogen fluoride source releases HF and may optionally slowly dissolve, completely or in part. The equilibrium reaction of HF formation is catalyzed in the presence of strong acid. Examples of such solid hydrogen fluoride sources are hydrofluoric acid, ammonium fluoride, ammonium bifluoride, fluoroboric acid, hexafluorophosphoric acid, difluorophosphoric acid, fluorosulfonic acid, polyvinylammonium fluoride, polyvinylpyridinium fluoride, pyridinium fluoride, imidazolium fluoride, sodium tetrafluoroborate, ammonium tetrafluoroborate, salts of hexafluoroantimony, polytetrafluoroethylene polymers (e.g. TEFLON® ), and combinations of these.

In certain embodiments of the invention, the source of hydrogen fluoride may be ammonium bifluoride, although others sources of hydrogen fluoride may be used, such as ammonium fluoride and HF. The hydrogen fluoride source may be used in an amount of from about 10% or more by weight of the slurry, more particularly from about 10% to about 60% by weight of slurry, more particularly, from about 15% to about 50% by weight, and still more particularly, from about 20% to about 45% by weight of slurry. When the hydrogen fluoride source is ammonium bifluoride, it may be present in the final slurry in an amount between about 10 and about 50% by weight, more particularly between about 15 and about 30% by weight, and still more particularly between about 20 and about 25% by weight. When the hydrogen fluoride source is ammonium fluoride, greater amounts may be used. For ammonium fluoride, it may be present in the final slurry in an amount between about 20 and about 60% by weight, more particularly between about 30 and about 50% by weight, and still more particularly between about 35 and about 45% by weight.

It should be understood that throughout this specification, when a concentration or amount range is described as being useful, or suitable, or the like, it is intended that any and every concentration or amount within the range, including the end points, is to be considered as having been stated. Furthermore, each numerical value should be read once as modified by the term “about” (unless already expressly so modified) and then read again as not to be so modified unless otherwise stated in context. For example, “a range of from 1 to 10” is to be read as indicating each and every possible number along the continuum between about 1 and about 10. In other words, when a certain range is expressed, even if only a few specific data points are explicitly identified or referred to within the range, or even when no data points are referred to within the range, it is to be understood that the inventor(s) appreciate and understand that any and all data points within the range are to be considered to have been specified, and that the inventor(s) have possession of the entire range and all points within the range.

The solid hydrogen fluoride source particles are encapsulated in a suitable encapsulating agent. The hydrogen fluoride source may make up from about 50% to 99% by weight of the encapsulated particles, with the encapsulating material constituting from about 1% to about 50% by weight of the particles. The encapsulating material may make up from about 0.1% to about 30% by weight or more of the slurry. The size of the encapsulating material may vary depending upon the desired amount of HF precursor to be released and/or the desired rate at which the precursor is to be released, depending upon the release mechanism. For example, if the HF source is released by diffusion through the capsule membrane, the thicker the encapsulating membrane or coating, the slower the release.

The encapsulated hydrogen fluoride source particles are pumped downhole, and therefore, may have a particle size that is similar to that of proppant or other particles for which the equipment is capable transporting downhole. The particles used for a given treatment may be of the same or different sizes. Suitable particle sizes may from about 0.1 mm to about 2 mm, more particularly from about 0.2 mm to about 1 mm, still more particularly from about 0.4 mm to about 0.85 mm (˜20-40 mesh).

Various types of encapsulating materials are encompassed within the invention. The encapsulating agent provides temporary encapsulation that subsequently releases the hydrogen fluoride source under predetermined conditions. These conditions may include temperature, pH, pressure or other conditions that deteriorate, dissolve, degrade, penetrate or break the encapsulating material. In the context of well stimulation, the coating material may release the HF source to the well treatment fluid by crushing of the particles due to the closure of the formation. In other cases, the encapsulating material is degraded under the conditions existing in the subterranean formation (e.g. pressure and temperature). A combination of two or more release mechanisms may also be employed. Release by osmosis may also be employed.

In certain embodiments, the encapsulating material may be solid polymeric acid precursors. These materials are typically solids at room temperature and are described in pending U.S. patent application Ser. No. 11/562,026, filed Nov. 21, 2006. The polymeric acid precursor materials include the polymers and oligomers that hydrolyze or degrade in certain chemical environments under known and controllable conditions of temperature, time and pH to release organic acid molecules that may be referred to as “monomeric organic acids.” As used herein, the expression “monomeric organic acid” or “monomeric acid” may also include dimeric acid or acid with a small number of linked monomer units that function similarly, for purposes of the invention described herein, to monomer acids composed of only one monomer unit.

The polymers for such materials may include those polyesters obtained by polymerization of hydroxycarboxylic acids, such as the aliphatic polyester of lactic acid, referred to as polylactic acid; glycolic acid, referred to as polyglycolic acid; 3-hydroxbutyric acid, referred to as polyhydroxybutyrate; 2-hydroxyvaleric acid, referred to as polyhydroxyvalerate; epsilon caprolactone, referred to as polyepsilon caprolactone or polyprolactone; the polyesters obtained by esterification of hydroxyl aminoacids such as serine, threonine and tyrosine; and the copolymers obtained by mixtures of the monomers listed above. A general structure for the above-described homopolyesters is:

H—{O—[C(R1,R2)]_(x)-[C(R3,R4)]_(y)-C═O}_(z)—OH   (1)

where,

R1, R2, R3, R4 is either H, linear alkyl, such as CH₃, CH₂CH₃ (CH₂)_(n)CH₃, branched alkyl, aryl, alkylaryl, a functional alkyl group (bearing carboxylic acid groups, amino groups, hydroxyl groups, thiol groups, or others) or a functional aryl group (bearing carboxylic acid groups, amino groups, hydroxyl groups, thiol groups, or others);

x is an integer between 1 and 11;

y is an integer between 0 and 10; and

z is an integer between 2 and 50,000.

In the appropriate conditions (pH, temperature, water content) polyesters like those described herein can hydrolyze and degrade to yield hydroxycarboxylic acid and compounds that pertain to those acids referred to in the foregoing as “monomeric acids.”

One example of a suitable polymeric acid precursor, as mentioned above, is the polymer of lactic acid, sometimes called polylactic acid, “PLA,” polylactate or polylactide. Lactic acid is a chiral molecule and has two optical isomers. These are D-lactic acid and L-lactic acid. The poly(L-lactic acid) and poly(D-lactic acid) forms are generally crystalline in nature. Polymerization of a mixture of the L- and D-lactic acids to poly(DL-lactic acid) results in a polymer that is more amorphous in nature. The polymers described herein are essentially linear. The degree of polymerization of the linear polylactic acid can vary from a few units (2-10 units) (oligomers) to several thousands (e.g. 2000-5000). Cyclic structures may also be used. The degree of polymerization of these cyclic structures may be smaller than that of the linear polymers. These cyclic structures may include cyclic dimers.

Another example is the polymer of glycolic acid (hydroxyacetic acid), also known as polyglycolic acid (“PGA”), or polyglycolide. Other materials suitable as polymeric acid precursors are all those polymers of glycolic acid with itself or other hydroxy-acid-containing moieties, as described in U.S. Pat. Nos. 4,848,467; 4,957,165; and 4,986,355.

The polylactic acid and polyglycolic acid may each be used as homopolymers, which may contain less than about 0.1% by weight of other comonomers. As used with reference to polylactic acid, “homopolymer(s)” is meant to include polymers of D-lactic acid, L-lactic acid and/or mixtures or copolymers of pure D-lactic acid and pure L-lactic acid. Additionally, random copolymers of lactic acid and glycolic acid and block copolymers of polylactic acid and polyglycolic acid may be used. Combinations of the described homopolymers and/or the above-described copolymers may also be used.

Other examples of polyesters of hydroxycarboxylic acids that may be used as polymeric acid precursors are the polymers of hydroxyvaleric acid (polyhydroxyvalerate), hydroxybutyric acid (polyhydroxybutyrate) and their copolymers with other hydroxycarboxylic acids. Polyesters resulting from the ring opening polymerization of lactones such as epsilon caprolactone (polyepsiloncaprolactone) or copolymers of hydroxyacids and lactones may also be used as polymeric acid precursors.

Polyesters obtained by esterification of other hydroxyl-containing acid-containing monomers such as hydroxyaminoacids may be used as polymeric acid precursors. Naturally occuring aminoacids are L-aminoacids. Among the 20 most common aminoacids the three that contain hydroxyl groups are L-serine, L-threonine, and L-tyrosine. These aminoacids may be polymerized to yield polyesters at the appropriate temperature and using appropriate catalysts by reaction of their alcohol and their carboxylic acid group. D-aminoacids are less common in nature, but their polymers and copolymers may also be used as polymeric acid precursors.

NatureWorks, LLC, Minnetonka, Minn., USA, produces solid cyclic lactic acid dimer called “lactide” and from it produces lactic acid polymers, or polylactates, with varying molecular weights and degrees of crystallinity, under the generic trade name NATUREWORKS™ PLA. The PLA's currently available from NatureWorks, LLC have number averaged molecular weights (Mn) of up to about 100,000 and weight averaged molecular weights (Mw) of up to about 200,000, although any polylactide (made by any process by any manufacturer) may be used. Those available from NatureWorks, LLC typically have crystalline melt temperatures of from about 120 to about 170° C., but others are obtainable. Poly(d,l-lactide) at various molecular weights is also commercially available from Bio-Invigor, Beijing and Taiwan. Bio-Invigor also supplies polyglycolic acid (also known as polyglycolide) and various copolymers of lactic acid and glycolic acid, often called “polyglactin” or poly(lactide-co-glycolide).

The extent of the crystallinity can be controlled by the manufacturing method for homopolymers and by the manufacturing method and the ratio and distribution of lactide and glycolide for the copolymers. Additionally, the chirality of the lactic acid used also affects the crystallinity of the polymer. Polyglycolide can be made in a porous form. Some of the polymers dissolve very slowly in water before they hydrolyze.

In the present invention, amorphous polymers may be particularly useful because they are more readily dissolved than crystalline polymers within the solvents described herein. An example of a suitable commercially available amorphous polymer is that available as NATUREWORKS 4060D PLA, available from NatureWorks, LLC, which is a poly(DL-lactic acid) and contains approximately 12% by weight of D-lactic acid and has a number average molecular weight (Mn) of approximately 98,000 g/mol and a weight average molecular weight (Mw) of approximately 186,000 g/mol.

Other polymer materials that may be useful are the polyesters obtained by polymerization of polycarboxylic acid derivatives, such as dicarboxylic acids derivatives with polyhydroxy containing compounds, in particular dihydroxy containing compounds. Polycarboxylic acid derivatives that may be used are those dicarboxylic acids such as oxalic acid, propanedioic acid, malonic acid, fumaric acid, maleic acid, succinic acid, glutaric acid, pentanedioic acid, adipic acid, phthalic acid, isophthalic acid, terphthalic acid, aspartic acid, or glutamic acid; polycarboxylic acid derivatives such as citric acid, poly and oligo acrylic acid and methacrylic acid copolymers; dicarboxylic acid anhydrides, such as, maleic anhydride, succinic anhydride, pentanedioic acid anhydride, adipic anhydride, phthalic anhydride; dicarboxylic acid halides, primarily dicarboxylic acid chlorides, such as propanedioic acyl chloride, malonyl chloride, fumaryl chloride, maleyl chloride, succinyl chloride, glutaroyl chloride, adipyl chloride, phthaloyl chloride. Useful polyhydroxy containing compounds are those dihydroxy compounds such as ethylene glycol, propylene glycol, 1,4 butanediol, 1,5 pentanediol, 1,6 hexanediol, hydroquinone, resorcinol, bisphenols such as bisphenol acetone (bisphenol A) or bisphenol formaldehyde (bisphenol F); polyols such as glycerol. When both a dicarboxylic acid derivative and a dihydroxy compound are used, a linear polyester results. It is understood that when one type of dicaboxylic acid is used, and one type of dihydroxy compound is used, a linear homopolyester is obtained. When multiple types of polycarboxylic acids and/or polyhydroxy containing monomer are used copolyesters are obtained. According to the Flory Stockmayer kinetics, the “functionality” of the polycarboxylic acid monomers (number of acid groups per monomer molecule) and the “functionality” of the polyhydroxy containing monomers (number of hydroxyl groups per monomer molecule) and their respective concentrations, will determine the configuration of the polymer (linear, branched, star, slightly crosslinked or fully crosslinked). All these configurations can be hydrolyzed or “degraded” to carboxylic acid monomers, and therefore can be considered as polymeric acid precursors. As a particular case example, not willing to be comprehensive of all the possible polyester structures one can consider, but just to provide an indication of the general structure of the most simple case one can encounter, the general structure for the linear homopolyesters of the invention is:

H—{O—R1-O—C═O—R2-C═O}_(z)—OH   (2)

where,

R1 and R2, are linear alkyl, branched alkyl, aryl, alkylaryl groups; and

z is an integer between 2 and 50,000.

Other examples of suitable polymeric acid precursors are the polyesters derived from phthalic acid derivatives such as polyethylenetherephthalate (PET), polybutylentetherephthalate (PBT), polyethylenenaphthalate (PEN), and the like.

In the appropriate conditions (pH, Temperature, water content) polyesters like those described herein can “hydrolyze” and “degrade” to yield polycarboxylic acids and polyhydroxy compounds, irrespective of the original polyester being synthesized from either one of the polycarboxylic acid derivatives listed above. The polycarboxylic acid compounds the polymer degradation process will yield are also considered monomeric acids.

Other examples of polymer materials that may be used are those obtained by the polymerization of sulfonic acid derivatives with polyhydroxy compounds, such as polysulfones or phosphoric acid derivatives with polyhydroxy compounds, such as polyphosphates.

The solid hydrogen fluoride source may be coated by the polymer acid precursor by a variety of methods. As an example, in one particular embodiment, the polymer acid precursor is dissolved in a suitable solvent. The solvents used for dissolving the polymeric acid precursors are herein referred to as “polymer dispersing solvents” or “dispersing solvents.” Such solvents are described in U.S. patent application Ser. No. 11/562,026, filed Nov. 21, 2006, which is herein incorporated by reference in its entirety. The polymer dispersing solvent may be any solvent that is capable of dispersing the polymeric acid precursor polymer molecules into a dispersed mixture of the polymer molecules within the solvent, as is more fully described below, and which does not tend to readily degrade or depolymerize the polymers themselves to their monomeric organic acids during the dissolution process. Additionally, the solvent or coating conditions (e.g. temperature, etc.) should be selected so that solid fluoride source is not readily dissolved or degraded as it is being coated.

Suitable solvents are organic solvents; in particular, organic solvents such as dibasic esters have been found to be particularly useful as the polymer dispersing solvent. Examples of suitable dibasic esters include dimethyl succinate (DBE-4), dimethyl glutarate (DBE-5), dimethyl adipate (DBE-6), and mixtures of these. Other suitable solvents are those dibasic esters of longer alkyl chain lengths, such as ethyl, propyl, butyl, hexyl, 2-ethylhexyl, phenyl and others. Other non-aliphatic dicarboxilic acid esters are also suitable, particularly for higher temperature applications, such as dimetylphthalate, dietylphthalate, dibutylphthalate, bis-2-ethylhexylphthalate, bisdodecylphthalate, and the like.

Additionally, some ketones, such as acetone, methylethyl ketone (MEK), methylisobutyl ketone (MIBK) and others, and some monobasic acid esters, such as ethyl acetate (EtOAc), methyl acetate, methyl formate, ethylformate, butyl acetate, and some ethers, such as diethylether and methylethyl ether, may be used as the polymer dispersing solvents. Other monobasic or dibasic acid esters with other alcohol chains such as longer linear or branched alkyl chains (C2-C24) such as ethyl, propyl, butyl, 2-ethyl hexyl, dodecyl, lauryl, steraryl, palmitoil, tetradecyl, cocoalkyl, octadecyl, oleyl, linoleil, linolenyl, tridecyl, undecyl, erudicyl, or aryl chains, such as phenyl, alykylphenyl or cycloalkyl chains, such as cyclohexyl, cyclopentyl, may also be suitable for some applications.

The polymeric acid precursors may be dissolved by the polymer dispersing solvents described so that they are no longer in solid form. As used herein, dissolving of the polymeric acid precursor in the polymer dispersing solvent is distinguished from the “degradation” of the precursor through a hydrolysis or transesterfication process that results in the generation of the monomeric organic acids derived from the polymeric acid precursors. The dissolution process involves a true molecular solution of the polymeric acid precursor in the polymer dispersing solvent in such a way that only a negligible decrease of the molecular weight of the polymer may be observed, as well as a negligible increase of the monomeric organic acid content. Accordingly, as used herein, the terms “dissolve,” “dissolving” and like expressions are meant to refer to the dissolving of the solid polymeric acid precursors so that they are no longer in solid form within the solvent, while essentially remaining in their polymeric form.

Similarly, as used herein, the terms “degrade,” “degrading,” and like expressions with reference to the polymeric acid precursor, are meant to refer to the formation of the monomeric organic acids that result from total hydrolysis of the of the polymeric acid precursors. Oligomers of the monomer may be formed due to partial degradation of the polymer, as well.

The polymer acid precursor and solid hydrogen fluoride source particles are combined in the solvent. The amount of solvent used may be sufficient to dissolve all or substantially all of the solid acid precursor material. Heating may be used, if necessary, to facilitate dissolution of the polymer acid precursor. The solution of polymer acid precursor and the solid hydrogen fluoride source is mixed and the solvent is evaporated to remove the solvent so that the solid HF source particles are coated with the polymer acid precursor. The amount of solid polymer acid precursor used may be that to provide the desired weight of coating on the HF source mixture. For example, an encapsulated particle that is to be approximately 75% by total weight as HF source particles, with approximately 25% by total weight of a polymer acid precursor coating, would be formed from a mixture of about 75% by weight of the HF source particles and about 25% by weight of the dissolved acid precursor.

Spray coating the dissolved acid precursor onto the solid HF source particles may also be used.

Other encapsulating materials may also be used. The choice of material will depend on a variety of factors such as the physical and chemical properties of the material being employed. Coating material can be from one of these categories: aqueous and organic solutions, dispersions, and hot melts. Nonlimiting examples of encapsulating materials include acrylics, halocarbon, polyvinyl alcohol, Aquacoat® aqueous dispersions, hydrocarbon resins, polyvinyl chloride, Aquateric® enteric coatings, hydroxypropyl cellulose (HPC), polyvinylacetate phthalate, hydroxypropyl methyl cellulose (HPMC), polyvinylidene chloride, hydroxylpropyl methyl cellulose phthalate (HPMCP), proteins, Kynar®, fluoroplastics, rubber (natural or synthetic), caseinates, maltodextrins, shellac, chlorinated rubber, silicone, polyvinyl acetate phtalate (e.g. Coateric®) coatings, microcrystalline wax, starches, coating butters, milk solids, stearines, polyvinyl dichloride (Daran®) latex, molasses, sucrose, dextrins, nylon, surfactants, Opadry® coating systems, Surelease® coating systems, enterics, paraffin wax, Teflon® fluorocarbons, Eudragits® polymethacrylates, phenolics, waxes, ethoxylated vinyl alcohol, vinyl alcohol copolymer, polylactides, zein, fats, polyamino acids, fatty acids, polyethylene gelatin, polyethylene glycol, glycerides, polyvinyl acetate, vegetable gums and polyvinyl pyrrolidone.

Encapsulating of the HF source particles with these materials may depend upon the encapsulating materials themselves. Some of these materials may be sprayed on the hydrogen fluoride source particles, which may be agitated in a fluidized bed, as a solution, molten material, emulsion, suspension, etc. The coating process would continue until the desired amount and/or thickness of the encapsulating layer is achieved.

Once suitably encapsulated, the encapsulated hydrogen fluoride source is combined with a carrier fluid. The carrier fluid may be an aqueous fluid that has been viscosified to ensure the heterogeneous placement of the encapsulated particles within the fracture. The carrier fluid may be sufficiently viscosified so that settling of the encapsulated particles does not occur. Accordingly, viscosifying agents may be added to water or other aqueous fluids, such as brine.

The viscosifying agent may be a polymer that is either crosslinked or linear, a viscoelastic surfactant, or any combination thereof. Some nonlimiting examples of suitable polymers include guar gums, high-molecular weight polysaccharides composed of mannose and galactose sugars, or guar derivatives such as hydropropyl guar (HPG), carboxymethyl guar (CMG), and carboxymethylhydroxypropyl guar (CMHPG). Cellulose derivatives such as hydroxyethylcellulose (HEC) or hydroxypropylcellulose (HPC) and carboxymethylhydroxyethylcellulose (CMHEC) may also be used. Any useful polymer may be used in either crosslinked form, or without crosslinker in linear form. Xanthan, diutan, and scleroglucan, three biopolymers, have been shown to be useful as viscosifying agents. Synthetic polymers such as, but not limited to, polyacrylamide and polyacrylate polymers and copolymers are used typically for high-temperature applications. Nonlimiting examples of suitable viscoelastic surfactants useful for viscosifying some fluids include cationic surfactants, anionic surfactants, zwitterionic surfactants, amphoteric surfactants, nonionic surfactants, and combinations thereof. Also, associative polymers for which viscosity properties are enhanced by suitable surfactants and hydrophobically modified polymers can be used, such as cases where a charged polymer in the presence of a surfactant having a charge that is opposite to that of the charged polymer, the surfactant being capable of forming an ion-pair association with the polymer resulting in a hydrophobically modified polymer having a plurality of hydrophobic groups, as described in published application U.S. 2004/0209780A1, Harris et. Al., herein incorporated by reference.

In some embodiments, the viscosifier may be a water-dispersible, linear, nonionic, hydroxyalkyl galactomannan polymer or a substituted hydroxyalkyl galactomannan polymer. Examples of useful hydroxyalkyl galactomannan polymers include, but are not limited to, hydroxy-C₁-C₄-alkyl galactomannans, such as hydroxy-C₁-C₄-alkyl guars. Examples of such hydroxyalkyl guars include hydroxyethyl guar (HE guar), hydroxypropyl guar (HP guar), and hydroxybutyl guar (HB guar), and mixed C₂-C₄, C₂/C₃, C₃/C₄, or C₂/C₄ hydroxyalkyl guars. Hydroxymethyl groups can also be present in any of these.

As used herein, substituted hydroxyalkyl galactomannan polymers are obtainable as substituted derivatives of the hydroxy-C₁-C₄-alkyl galactomannans, which include: 1) hydrophobically-modified hydroxyalkyl galactomannans, e.g., C₁-C₁₈-alkyl-substituted hydroxyalkyl galactomannans, e.g., wherein the amount of alkyl substituent groups is preferably about 2% by weight or less of the hydroxyalkyl galactomannan; and 2) poly(oxyalkylene)-grafted galactomannans (see, e.g., A. Bahamdan & W. H. Daly, in Proc. 8PthP Polymers for Adv. Technol. Int'l Symp. (Budapest, Hungary, September 2005) (PEG- and/or PPG-grafting is illustrated, although applied therein to carboxymethyl guar, rather than directly to a galactomannan)). Poly(oxyalkylene)-grafts thereof can comprise two or more than two oxyalkylene residues; and the oxyalkylene residues can be C₁-C₄ oxyalkylenes. Mixed-substitution polymers comprising alkyl substituent groups and poly(oxyalkylene) substituent groups on the hydroxyalkyl galactomannan are also useful herein. In various embodiments of substituted hydroxyalkyl galactomannans, the ratio of alkyl and/or poly(oxyalkylene) substituent groups to mannosyl backbone residues can be about 1:25 or less, i.e. with at least one substituent per hydroxyalkyl galactomannan molecule; the ratio can be: at least or about 1:2000, 1:500, 1:100, or 1:50; or up to or about 1:50, 1:40, 1:35, or 1:30. Combinations of galactomannan polymers can also be used.

As used herein, galactomannans comprise a polymannose backbone attached to galactose branches that are present at an average ratio of from 1:1 to 1:5 galactose branches:mannose residues. Preferred galactomannans comprise a 1→4-linked β-D-mannopyranose backbone that is 1→6-linked to α-D-galactopyranose branches. Galactose branches can comprise from 1 to about 5 galactosyl residues; in various embodiments, the average branch length can be from 1 to 2, or from 1 to about 1.5 residues. Preferred branches are monogalactosyl branches. In various embodiments, the ratio of galactose branches to backbone mannose residues can be, approximately, from 1:1 to 1:3, from 1:1.5 to 1:2.5, or from 1:1.5 to 1:2, on average. In various embodiments, the galactomannan can have a linear polymannose backbone. The galactomannan can be natural or synthetic. Natural galactomannans useful herein include plant and microbial (e.g., fungal) galactomannans, among which plant galactomannans are preferred. In various embodiments, legume seed galactomannans can be used, examples of which include, but are not limited to: tara gum (e.g., from Cesalpinia spinosa seeds) and guar gum (e.g., from Cyamopsis tetragonoloba seeds). In addition, although embodiments of the present invention may be described or exemplified with reference to guar, such as by reference to hydroxy-C₁-C₄-alkyl guars, such descriptions apply equally to other galactomannans, as well.

When incorporated, the polymer-based viscosifier may be present at any suitable concentration to provide the desired dispersion of the encapsulated hydrogen fluoride source. In certain embodiments, the viscosifying agent can be present in an amount of from about 0.1 wt. % to about 5 wt. % of total weight of treating fluid or less. The fluids incorporating the polymer may have any suitable viscosity, for example, a viscosity value of greater than about 20 mPa-s or greater at a shear rate of about 100 s-1 at treatment temperature, more particularly about 50 mPa-s or greater at a shear rate of about 100 s-1, and even more particularly about 75 mPa-s or greater. Depending upon the density of the encapsulated particles, the viscosity required may be less than that used for suspending conventional proppant materials used in fracturing treatments.

In some embodiments of the invention, a viscoelastic surfactant (VES) is used as the viscosifying agent. The VES may be selected from the group consisting of cationic, anionic, zwitterionic, amphoteric, nonionic surfacatants and combinations thereof. U.S. Pat. Nos. 6,435,277 (Qu et al.) and 6,703,352 (Dahayanake et al.), each of which are incorporated herein by reference, describe non-limiting examples of suitable viscoelastic surfactants. The viscoelastic surfactants, when used alone or in combination, are capable of forming micelles that form a structure in an aqueous environment that contribute to the increased viscosity of the fluid (also referred to as “viscosifying micelles”). These fluids are normally prepared by mixing in appropriate amounts of VES suitable to achieve the desired viscosity. The viscosity of VES fluids may be attributed to the three dimensional structure formed by the components in the fluids. When the concentration of surfactants in a viscoelastic fluid significantly exceeds a critical concentration, and in most cases in the presence of an electrolyte, surfactant molecules aggregate into species such as micelles, which can interact to form a network exhibiting viscous and elastic behavior.

When a VES is incorporated into fluids used in embodiments of the invention, the VES can range from about 0.2% to about 15% by weight of total weight of fluid, more particularly, from about 0.5% to about 15% by weight of total weight of fluid, more particularly, from about 2% to about 10% by weight of total weight of fluid. The lower limit of VES may be no less than about 0.2, 0.5, 0.7, 0.9, 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, or 14 percent of total weight of fluid, and the upper limit may be no more than about 15 percent of total fluid weight, specifically no greater than about 15, 14, 13, 12, 11, 10, 9, 8, 7, 6, 5, 1, 0.9, 0.7, 0.5 or 0.3 percent of total weight of fluid. Fluids incorporating VES based viscosifiers may have any suitable viscosity, for example, a viscosity value of about 20 mPa-s or greater at a shear rate of about 100 s-1 at treatment temperature, more particularly about 50 mPa-s or greater at a shear rate of about 100 s-1, and even more particularly about 75 mPa-s or greater. Again, depending upon the density of the encapsulated particles, the viscosity required may be less than that used for suspending conventional proppant materials used in fracturing treatments.

In most cases, the carrier fluid is an acid-based carrier fluid. The carrier fluid is acidized with non-HF acids or non-HF acid precursors. This may include mixtures of acids. The acids used with the carrier fluid may include, but are not limited to, hydrochloric acid, hydroiodic acid, hydrobromic acid, sulfuric acid, sulfamic acid, phosphoric acid, formic acid, acetic acid, halogenated derivatives of acetic acid, citric acid, propionic acid, tartaric acid, lactic acid, glycolic acid, aminopolycarboxylic acids, sulfamic acid, malic acid, maleic acid, methylsulfamic acid, chloroacetic acid, 3-hydroxypropionic acid, polyaminopolycarboxylic acid, bisulfate salts and combinations of these.

The acids may be used in an amount to provide a pH of about 4 or less once injected into the formation. The initial pH at the surface may be higher than the pH of fluid after it is introduced into the formation. Lower pH may be attained subsequent to introduction of the slurry into the formation due to higher temperatures and the formation of acids from acid precursor materials.

When the HF source is encapsulated with a polymeric acid precursor, as described above, the carrier fluid may be initially non-acidic or neutral pH. Once introduced into the formation, the solid acid precursor will degrade to form acid to provide an acidic pH of about 4 or less for the fluids injected into the formation so that the hydrogen fluoride source is dissolved to release hydrogen fluoride.

Chelating agents may also be added to the carrier fluid to prevent undesired precipitation of various materials with metal ions resulting from the reaction of the hydrofluoric acid with the formation. The chelating agents may be used in an amount of from about 10% to about 40% by weight of the carrier fluid. Suitable chelating agents include those described in U.S. Patent Publication No. 2004/00254079, which is herein incorporated by reference in its entirety. Examples of suitable chelating agents include malic acid, tartaric acid, citric acid, certain aminopolycarboxylate and polyaminopolycarboxylate chelating agents (such as, by non-limiting example, NTA (nitrilotriacetic acid), HEIDA (hydroxyethlimnodiacetic acid), HEDTA (hydroxyethylethylenediaminet-etraacetic acid, EDTA (ethylenediaminetetraacetic acid), CyDTA (cyclohexylenediaminetetraacetic acid), DTPA (diethylenetriaminepentaacet-ic acid)) and certain aminopolymethylenephosphonic acid chelating agents and their salts, and mixtures of these materials.

Corrosion inhibitors may also be added to the treatment fluids. Conventional corrosion inhibitors may be used as long as they are compatible with chemicals present in, or generated during use by, the slurry. Compounds containing quaternary ammonium moieties and sulfur compounds may be suitable (see for example U.S. Pat. No. 6,521,028).

Other additives commonly used in oilfield treatment fluids, such as friction reducers, clay control additives, wetting agents, fluid loss additives, emulsifiers, agents to prevent the formation of emulsions, foaming agents, scale inhibitors, fibers, breakers and consolidating materials may also be used. It is to be understood that whenever any additives are included, laboratory tests may be performed to ensure that the additives do not affect the performance of the fluid.

In treating a sandstone formation to provide heterogeneous etching, if the formation contains any carbonate the formation may be pretreated (preflushed) with an acid, such as hydrochloric acid, to dissolve the carbonate. If necessary, a spacer such as ammonium chloride may then be injected to push dissolved materials away before injection of the encapsulated-HF-source-containing fluid so that released fluoride ions do not contact cations such as sodium, aluminum, calcium and magnesium, which could precipitate. Chelating agents for cations such as aluminum, calcium and magnesium may be added to any of the fluids or mixtures of the invention. If the slurry containing the encapsulated HF source contains sufficient chelating agent, the preflush may not be necessary.

Typically in fracturing treatments, injection of a fluid ahead of the main treatment fluid is employed to create width. A pad may be used in the present invention to ensure that the fracture is wide enough for the solids in the main fluid to enter, but optionally the pad stage may be eliminated. The pad may be any viscous fluid, such as fluids viscosified with polymers, crosslinked polymers, VES, and foams, and may itself comprise a formation dissolving material or a clay control agent.

The slurry containing the carrier fluid, viscosifying agent and encapsulated hydrogen fluoride source, along with any other additives, is formed at the surface. All of the different components may be individually manufactured, stored, transported to a job site, and added in any order to an aqueous fluid to make the fracturing fluid slurry that is then injected into a well. The slurry may be batch mixed or mixed on-the-fly, although the latter is preferred.

The formed slurry is injected into the formation at a pressure and rate sufficient to fracture the portion of the formation being treated. In certain instances, the well may then be shut in for a period time, maintaining the pressure above the fracture pressure. The shut in time may be from an hour or more, but is typically from about 2 to about 24 hours. In other instances, the pressure may be reduced so that the fracture closes. The closing of the fracture may facilitate crushing or breaking of the encapsulating material so that the hydrogen fluoride source is exposed to release the hydrogen fluoride.

In the case of HF source particles encapsulated with a solid acid precursor, the aqueous environment and elevated temperature of the subterranean formation causes the acid precursor to hydrolyze or degrade to its monomeric acids. This causes the fluids within the fracture to become acidic or more acidic. Additionally, the HF source is exposed and the acidic fluid environment causes the HF source to release hydrogen fluoride to react with the sandstone faces of the fracture.

Because the encapsulated HF source is dispersed within the carrier fluid within the fracture, high concentrations of the HF etching agent at different isolated locations throughout the fracture result in the heterogeneous etching of the sandstone formation. This results in differential etching of the formation to provide flow channels once the pressure is released and the fracture is closed and provides increased production of fluids from the treated formation through the wellbore.

The following example serves to further illustrate the invention.

EXAMPLES Example

This example shows the effect of encapsulated ammonium bifluoride on the surface dissolution of Berea sandstone. Core samples of solid cylindrical disks of Berea sandstone measuring approximately 4″ (10 cm) in diameter and 0.8″ (2 cm) thick were used. FIG. 1 shows a Berea sandstone core sample prior to treatment.

Static etch tests were conducted with aqueous treatment fluids employing 23 wt. % of ammonium bifluoride encapsulated with a polyurethane coating. The polyurethane coating made up approximately 30% wt. % of the encapsulated material. The polyurethane coating material is affected by temperature. Polylactic acid (PLA) particles having a particle size of 20-40 mesh (˜0.84 mm to 0.42 mm) having a molecular weight of from 100 to 1000 kDalton supplied by NatureWorks LLC were combined with the fluid in an amount of 11.7 wt. % to acidize the fluid. The samples were compared with the same test performed with non-encapsulated ammonium bifluoride at the same concentration of ammonium bifluoride and PLA.

The cores were initially saturated with a solution of 5 wt. % NH₄Cl for 30 minutes in a vacuum chamber depressurized to 30 mm Hg. The static cell loading tests were then performed in a Parr pressure reactor on the core samples where the treatment fluid was placed between the core samples and then pressurized to 300 psi (˜2068 kPa) with N₂ gas. The system was then slowly heated to a target temperature of 300° F. (˜150° C.) and kept at temperature and pressure for at least 4 hours.

After 4 hours at 300° F., the surface of the core treated with the encapsulated ammonium bifluoride provided a differential etched pattern, as shown in FIG. 2. In contrast, a smooth surface was obtained from the treatment with the non-encapsulated ammonium bifluoride, as shown in FIG. 3.

While the invention has been shown in only some of its forms, it should be apparent to those skilled in the art that it is not so limited, but is susceptible to various changes and modifications without departing from the scope of the invention. Accordingly, it is appropriate that the appended claims be construed broadly and in a manner consistent with the scope of the invention. 

1. A method of treating a sandstone-containing subterranean formation penetrated by a wellbore comprising: forming a slurry of a carrier fluid containing a viscosifying agent and encapsulated particles of a hydrogen fluoride source, the encapsulated hydrogen fluoride source being dispersed within the slurry without settling of the particles and to provide heterogeneous placement of the particles, the hydrogen fluoride source being present in the slurry in an amount of about 10% to about 60% by weight of the slurry; and introducing the slurry into the wellbore at a pressure above the fracture pressure of the formation under conditions wherein the hydrogen fluoride source is released in a portion of the formation containing sandstone.
 2. The method of claim 1, wherein: the hydrogen fluoride source is encapsulated within a polylactic acid solid polymer acid precursor.
 3. The method of claim 1, wherein: the hydrogen fluoride source is encapsulated within a solid polymer acid precursor comprising at least one of homopolymers of lactic acid, glycolic acid, hydroxybutyrate, and hydroxyvalerate, random copolymers of at least two of lactic acid, glycolic acid, hydroxybutyrate, hydroxyvalerate, L-serine, L-threonine, L-tyrosine, block copolymers of at least two of polyglycolic acid, polylactic acid, hydroxybutyrate, hydroxyvalerate, L-serine, L-threonine, L-tyrosine, homopolymers of ethylenetherephthalate (PET), butylenetherephthalate (PBT) and ethylenenaphthalate (PEN), random copolymers of at least two of ethylenetherephthalate, butylenetherephthalate and ethylenenaphthalate, block copolymers of at least two of ethylenetherephthalate, butylenetherephthalate, ethylenenaphthalate and combinations of these.
 4. The method of claim 1, wherein: the hydrogen fluoride source is encapsulated within at least one of acrylics, halocarbon, polyvinyl alcohol, aqueous dispersions, hydrocarbon resins, polyvinyl chloride, enteric coatings, hydroxypropyl cellulose (HPC), polyvinylacetate phthalate, hydroxypropyl methyl cellulose (HPMC), polyvinylidene chloride, hydroxylpropyl methyl cellulose phthalate (HPMCP), proteins, fluoroplastics, rubber (natural or synthetic), caseinates, maltodextrins, shellac, chlorinated rubber, silicone, polyvinyl acetate phtalate coatings, microcrystalline wax, starches, coating butters, milk solids, stearines, polyvinyl dichloride latex, molasses, sucrose, dextrins, nylon, surfactants, combined polymer/plasticizer coating systems, a combination of film-forming polymer/plasticizer/stabilizers, enterics, paraffin wax, fluorocarbons, polymethacrylates, phenolics, waxes, ethoxylated vinyl alcohol, vinyl alcohol copolymer, polylactides, zein, fats, polyamino acids, fatty acids, polyethylene gelatin, polyethylene glycol, glycerides, polyvinyl acetate, vegetable gums and polyvinyl pyrrolidone.
 5. The method of claim 1, wherein: the encapsulating material makes up from about 0.1% to about 30% by weight of the slurry.
 6. The method of claim 1, wherein: the carrier fluid is an acid-based fluid.
 7. The method of claim 6, wherein: the carrier fluid includes hydrochloric acid, nitric acid, hydroiodic acid, hydrobromic acid, sulfuric acid, sulfamic acid, phosphoric acid, formic acid, acetic acid, halogenated derivatives of acetic acid, citric acid, propionic acid, tartaric acid, lactic acid, glycolic acid, aminopolycarboxylic acids, sulfamic acid, malic acid, maleic acid, methylsulfamic acid, chloroacetic acid, 3-hydroxypropionic acid, polyaminopolycarboxylic acid, bisulfate salts and combinations of these.
 8. The method of claim 1, wherein: the hydrogen fluoride source is selected from ammonium fluoride, ammonium bifluoride, fluoroboric acid, hexafluorophosphoric acid, difluorophosphoric acid, fluorosulfonic acid, polyvinylammonium fluoride, polyvinylpyridinium fluoride, pyridinium fluoride, imidazolium fluoride, sodium tetrafluoroborate, ammonium tetrafluoroborate, salts of hexafluoroantimony, polytetrafluoroethylene polymers, and combinations of these.
 9. The method of claim 1, wherein: the encapsulated particles have a particle size of from about 0.1 mm to about 2 mm.
 10. The method of claim 1, wherein: the hydrogen fluoride source makes up from about 50% to 99% by weight of the encapsulated particles.
 11. The method of claim 1, wherein: the pressure is maintained above the fracture pressure for a period of from one hour or more after the slurry is introduced into the well.
 12. The method of claim 1, wherein: the treatment results in an increased production of fluids from the wellbore.
 13. The method of claim 1, wherein: the hydrogen fluoride source is present in the slurry in an amount of from about 10% to about 50% by weight of the slurry.
 14. The method of claim 1, wherein: the hydrogen fluoride source is present in the slurry in an amount of from about 15% to about 50% by weight of the slurry.
 15. The method of claim 1, wherein: the hydrogen fluoride source is present in the slurry in an amount of from about 20% to about 45% by weight of the slurry.
 16. A method of treating a sandstone-containing subterranean formation penetrated by a wellbore comprising: forming a slurry of an acid-based carrier fluid containing a viscosifying agent and encapsulated particles of a hydrogen fluoride source, with the encapsulating material making up from about 0.1% to about 50% by weight of the encapsulated particles and wherein the encapsulated hydrogen fluoride source is dispersed within the slurry without settling of the particles and to provide heterogeneous placement of the particles, the hydrogen fluoride source being present in the slurry in an amount of about 10% to about 60% by weight or more of the slurry; and introducing the slurry into the wellbore under conditions wherein the hydrogen fluoride source is released in a portion of the formation containing sandstone to provide heterogeneous etching of faces of said portion of the formation.
 17. The method of claim 16 wherein the slurry is introduced into the wellbore at a pressure above the fracture pressure of the formation under conditions wherein the hydrogen fluoride source is released.
 18. The method of claim 16, wherein the hydrogen fluoride source is encapsulated within a polylactic acid solid polymer acid precursor.
 19. A method of treating a sandstone-containing subterranean formation penetrated by a wellbore comprising: forming a slurry of a carrier fluid containing a viscosifying agent and particles of a hydrogen fluoride source encapsulated with a solid polymer acid precursor, the encapsulated hydrogen fluoride source being dispersed within the slurry without settling of the particles and to provide heterogeneous placement of the particles, the hydrogen fluoride source being present in the slurry in an amount of about 10% to about 60% by weight; and introducing the slurry into the wellbore under conditions wherein the hydrogen fluoride source is released in a portion of the formation containing sandstone.
 20. The method of claim 19 wherein the slurry is introduced into the wellbore at a pressure above the fracture pressure of the formation under conditions wherein the hydrogen fluoride source is released. 